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Short-term Fixes Often Trump Major Component Replacements

Issue 8 and Volume 113.

Large component replacement work continues, despite harsh economic realities and other uncertainties.

By Steve Blankinship, Associate Editor

Despite a sagging economy and lowered electric demand, the power must stay on. That means repairs and upgrades to fossil power generation fleet continue. Some are small and intended to meet short-term needs.


Power plant owners are repoted to be spending for today rather than the future, waiting for economic conditions to improve. Photo courtesy Hobart Brothers.
Click here to enlarge image

“It’s a like having 40,000 miles on your tires and you get a hole in one of them,” said Mark Low, vice president of service projects for Babcock & Wilcox PGG. “Instead of getting a new set, power plant owners are just replacing the tire with the hole in it. They are spending for today rather than the future—waiting for things to get better.”

By some definitions, small fixes can include heaters, super heaters, reheaters and small economizers. Larger jobs include low NOX burners, boiler convection path replacement, water walls, boiler tubes, auxiliary boilers and large economizer and condenser replacements. Large jobs also include turbine generator uprates, often driven by the addition of scrubbers (FGD) and selective catalytic reduction (SCR). Turbine generator upgrades in some cases are needed to compensate for the additional parasitic load these environmental systems draw.

There are also a few examples of simple cycle units being converted to combined cycle plants. And at least one gas turbine manufacturer sees some activity with non-utility gas plants in the petrochemical/refinery sector, where the need for combined heat and power make gas units baseload resources.

Some additions of FGD and SCR are moving forward, most of which have been in the pipeline for a while or are being installed as the result of consent decrees or lawsuits. However, most major environmental retrofits have ground to a halt and major boiler repairs remain, for the most part, on the back burner for now.

Turbine/Generators

Today’s turbine technology can easily add additional capacity, reliability and increase the time between inspection intervals. As an example, inspection on a low-pressure turbine with 1970s-vintage technology is every five years. Inspection requires disassembling the entire section. Current technology permits stretching low-pressure turbine inspections to intervals of 100,000 hours, which equates to about 10 years of operation.

Dave Brubaker works the fossil side of Siemens’ turbine business and said most major work done at a coal-fired plant is done as a capital outage, with work scheduled in conjunction with a major boiler inspection and repair every three years or so. A typical “boiler major” runs 45 days or longer, and Brubaker is accustomed to fitting everything that needs to be done on a steam turbine into such a timeframe.

“We just work on the turbine and the customer is usually working on the boiler at the same time,” he said. In many cases, coal plants perform turbine work in conjunction with an emissions project, such as adding a scrubber. The scrubber adds parasitic load, so the plant needs to uprate the turbine to recover that output. No need exists to relicense the plant as a new source since there is no net gain in power output.

New source review is generally not required if there’s no change in the boiler’s thermal output. On the other hand, if the boiler is upgraded to produce more flow and higher firing temperatures, new source review can become an issue. A typical turbine uprate for a 500 MW to 600 MW plant receiving new emissions equipment might be 30 MW, or a 6 percent, improvement in output through efficiency without changing the flow.

Brubaker said another method for speeding major component replacement while lowering the cost involves pre-assembled stator stacks. Sometimes called a “doughnut” because of their shape, stator cores are composed of thousands of thin sheets made of laminated steel that used to take many weeks to restack. Siemens builds pre-assembled stacks, varying in thicknesses from six inches to several feet. Whereas rebuilding a core used to take six, eight or 12 weeks overall, the entire job can now be achieved in 28 to 30 days.

“We improve the inner casing and blade path and the rotor itself to provide better blading on the high pressure and intermediate sections of the turbine; the areas that are the most highly stressed and wear out first,” said Brubaker. “When we’re finished, they no longer need the control staging they did before.” That means the power plant can achieve higher efficiency at full load. One advantage is the flexibility that was designed into coal units years ago.

When uprating a coal plant steam turbine/generator, the generator must be analyzed to determine what the additional load will be. Generators often need rewinding once they reach about 40 years in age. “With our new insulating systems and analytical tools we are able to put more copper into existing slots and boost the capacity of those generators in addition to increasing their life,” said Brubaker.

“Anyone more than 20 years old has been around long enough to see technology improvements,” said Russell Voigt of Siemens. Although Voigt works on the nuclear side of Siemens’ turbine business, many of the same principles apply to fossil. “Blade design has become so advanced that with just minor tweaks you can gain megawatts,” he said. The steam going through low pressure nuclear turbine rotors is much wetter than in a fossil plant, meaning far more stress corrosion cracking. Inlet temperature on a fossil plant turbine is more than 1,000 F compared with 600 F for a nuclear turbine. That’s why nuclear turbines have moisture separators between the high pressure and low pressure turbines.

As a result, plants had to keep spare rotors in stock that they could install when they found a problem that couldn’t wait for a scheduled outage. That easily meant tens of millions of dollars invested in spare components.

One alternative to keeping expensive inventory is to improve blade design and configuration on the back end of the steam turbines and by installing denser rotor packs. This can add as much as 3 to 5 percent to cycle efficiency. Such rotor upgrade and replacement is estimated to cost $25 to $30 million. “We can replace a high pressure turbine in about 25 days and a low pressure turbine (depending on whether you have one, two or three of them) in 35 to 38 days,” Voigt said.

Most generators were designed to run 30 to 40 years. Today, power asset owners are trying to run them another 20 or 30 years. Fortunately, rewinding technology has improved since those old soldiers first entered service. “If you’re going to run another 20 years or more, you can spend a lot of money repairing them,” said Voigt, “or you can rewind them.” It’s also important to note that capacity added to the turbine might prove too much for the generator to handle without corresponding megawatt output to the generator in the form of rewinding and improvements in both the core and coil design.

The nuclear side has learned something about rewinds that can be applied to fossil plants. Voigt said a total generator rewind takes six to nine weeks, which is too long to be accomplished during a typical nuclear plant fuel outage that lasts less than three weeks. “We have overcome that by taking the stators that the winders and rotor go into from nuclear plants that were cancelled in the 1970s and winding the stator during the summer months. That’s when we have resources available since we’re not doing maintenance.”

Rather than rewind the stator during an outage, Siemens can pull the old stator off the foundation and put a new one on in three to four weeks. “All of this is applicable to the fossil side, even though their outages are longer,” he said.

To speed repaid and replacement work, Brubaker said Siemens focuses on eliminating non-value added steps. If we can eliminate some unnecessary steps and processes we can also pull out some costs,” he said. Siemens also is doing more hydraulic bolting instead of cold torque, which involves “yanking on a torque wrench.” A tensioner tensions the bolt and the worker spins the nut down and releases the tension off the tensioner, leaving the bolt tight. “Not only is it easier, it also shortens outages because when you go back to do maintenance it’s faster to bolt and unbolt,” he said.

A recently announced gas–fired project upgrade is for Calpine’s Siemens F Class gas turbines, with an option to upgrade additional units. The upgrades will add incremental capacity while improving engine efficiency. The thermal performance upgrade to the Siemens SGT6-5000F combustion turbine will increase baseload power while improving baseload heat rate.

Houston-based HPI was recently awarded a major turbine overhaul project with South Carolina Electric & Gas at the Hagood Generating Station near Charleston, N.C. The project will include the hot gas path inspection and four rows of blade removal/replacement with the rotor in place to a Westinghouse W501D5.

So far as converting simple cycle units to combined cycle, which requires adding heat recovery steam generators (HRSGs), Siemens recently completed a project for Tennessee Valley Authority’s Gleason plant.

Time constraints are not as critical in upgrading gas units as they are with coal units. After all, coal plants generate power so much more cheaply and are therefore relied upon more of the time. Don Broeils, vice president of plant betterment for Fluor and responsible for major environmental upgrades, said Fluor does everything it can in the field before the coal-fired generating unit comes down for final tie-in and restart. “Our outage schedules define what we’ll be doing each hour of each specific day,” he said. The company also tries to modularize and preassemble major parts of the tie-in components to have as few lifts as possible.

And because large environmental retrofits encounter major space constraint issues, an EPC must be creative in designing lifting and rigging to maneuver components into place.

“You can be under existing flues or right over a precipitator,” said Broeils. As a result, Fluor has a construction technology group that develops rigging and lifting plans to make the work move through the outage as smoothly and quickly as possible. “These are often engineered solutions that allow us to move the components in, complete the tie-in connections and get out of the way as quickly as possible,” he said. A typical tie-in for a major environmental upgrade takes several weeks followed by another couple of weeks for tuning and matching the scrubber or SCR to the unit. The overall construction project typically takes about 18 months.

Condensers

Condensers represent another major coal plant component replacement that becomes necessary after two or three decades of service. Geoff Greenberg, senior director of sales and marketing from Babcock Power’s Thermal Engineering International USA Inc. (TEi), described how TEi removes existing condenser tubes and redesigns the bundles to increase the surface area by 10 to 25 percent, thus improving condenser performance.

Condenser modules may be a viable alternative to retubing for any tube material. In many cases, if copper-based tubes are removed (which they often are for environmental and other issues) and retubed with stainless steel or titanium, performance may suffer because copper tubing’s heat transfer coefficient typically is better than replacement metals. Although copper-based tube materials were used for condenser tubes over many decades, small amounts of copper from condensers ended up in rivers and lakes used to cool the power plant. Copper also could leave deposits in turbines and boilers downstream, causing some damage.

“Many utilities have been trying to eliminate copper from their condensers,” said Greenberg. “We provide brand new condenser modules that have enough additional surface area to either get back to the original performance provided by the copper’s thermal properties or even improve upon that.”

The condenser module concept is based on removing the existing condenser tube bundles (tubes, tubesheets, support plates, and so on) and replacing them with newly designed tube bundles. The new modules are designed to the latest technologies and consist of new tubes, tubesheets, support plates and other internal components and enhancements. Condenser modules are typically fully shop-assembled but can be provided in sections or parts depending on accessibility to the existing condenser at the jobsite.

The module concept offers other advantages over just re-tubing. Re-tubing leaves the original tubesheets. “That could cause more harm than good,” he said. “Furthermore, repeated re-tubing, especially with copper-based tubesheets, could wear out the tubesheet and lead to serious problems during the outage. Replacing everything with new prefabricated modules eliminates those problems.”

TEi designs a complete new bundle of condenser internals fabricated in its shops in Missouri and Oklahoma. That includes new tubes, tubesheets and support plates, as well as additional intermediate support plates to control vibration. “Assuming we have clear access, we can probably install the module in a shorter outage time than re-tubing,” said Greenberg. “There can be anywhere from 10,000 to 20,000 tubes in a unit, and by the time you remove all those tubes, prep for new tubes and install them, you can probably pull out the existing bundle and get the new bundle in faster, thus saving outage time.”

Since performance is often improved, the payback can be quick. TEi recently completed a condenser module installation at Tampa Electric’s Big Bend Unit 1. The $5 million contract paid for itself over one summer. TEi also did a condenser upgrade for Ameren’s Callaway nuclear plant. The new modules were expected to boost power output by 4 MW, but the actual output increase was 9 MW. The utility stated that here, too, the multi-million dollar contract to TEi paid for itself over one summer.

Business Downturn

Still, however, overall business is off. Mark Low, vice president of service projects for Babcock & Wilcox, said power demand for some utilities is down by double-digit figures. “Industrial load is off, cash is tight, credit is tight and expensive,” he said. “The market has dropped since about the third quarter of last year on retrofits and service projects.”

He sees uncertainty about environmental legislation to be part of it. Questions exist around future greenhouse gas legislation and the Clean Air Interstate Rule, which a federal court said must be redrafted. Where the original CAIR was based on a cap and trade concept, the replacement may not be, said Low. That means the older, smaller capacity units that probably didn’t need to add SCRs and flue gas desulfurization equipment because credits were available might now choose to retire affected units instead of adding emissions equipment. “Uncertainty has reduced demand on retrofit markets,” he said.

John Koslosky, general manager of construction projects for Babcock & Wilcox, agreed that without the option of buying credits to offset large investments on smaller units, many owners will choose to shut units down.

While Koslosky sees many utilities tightening their belt, municipalities and co-ops continue to spend, possibly because they tap financial resources through the bond market or government backed loans. He sees boiler components such as super heaters being replaced, as well as reheater and burner upgrades to reduce NOX. He said such projects are not driven by the need for more capacity or more generation. Instead, units are old and need replacement part.

Koslosky also said he sees smaller projects that might include partial component replacement. He recalled how in better economic times utilities facing a long outage for major work would buy more components or more sections. They might upgrade the horizontal convection path or replace the whole back end. Today, the approach is just to change the minimum to meet current demands and pressures.

Renewables Drive Some Upgrades

Koslosky said he also sees additions to gas plant cycling capacity in Colorado and elsewhere to cover the intermittency of wind generation. He also sees interest in biomass picking up. “There are a lot of IPPs (independent power producers) involved in the biomass sector and they are relying on the credit markets. The IPPs would build greenfield plants of 35 MW to 50 MW in states that have, or will have, renewable portfolio standards.”

And he sees utilities considering converting some older units to burn biomass, such as First Energy looking at converting its Burger station to burn 100 percent biomass. And while utilities are also considering some amount of co-firing, much of that remains in the study stage at this time, he said.

The case for biomass retrofits might be compelling. Around 300,000 MW of current U.S. coal-fired capacity is over 35 years old and needs to be modernized. Converting that capacity to biomass could reduce coal consumption and carbon emissions. Because biomass is generally accepted as a carbon-neutral fuel, co-firing up to 5 percent can be done in most power plants. Even larger percentages could be achieved depending on boiler design. Boiler technology could be upgraded to a bubbling bed configuration or the plant could be repowered for circulating fluidized bed combustion. These measures could boost biomass to around 20 percent of the domestic fuel mix.

Repowering to allow co-firing of up to 20 percent biomass could improve net efficiency, with every 2 percent cycle efficiency improvement producing a 5 percent reduction of CO2 emissions. Such a change in boiler technology could be done in combination with turbine improvements as well as changes to variable speed drives in major components which could further improve efficiency.

Alstom has supplied about 42 percent of the large coal fired boilers in the U.S. And it is increasing its capabilities for the large component replacement business at its expanded factory in Chattanooga, Tenn. The Chattanooga site includes an existing boiler retrofit operation currently focused on maintaining and upgrading the existing U.S. fleet with large component replacements, and a new turbine manufacturing facility for both new and existing component markets.


A factory worker at Alstom’s Chattanooga, Tenn. manufacturing facility. Photo courtesy Alstom.
Click here to enlarge image

Alstom offers a broad power generation equipment portfolio for both new and retrofit requirements, including boilers, nuclear and fossil steam turbines, gas turbines, hydro turbines, generators, wind turbines, geothermal turbines and environmental equipment. “To serve the increasing needs of the U.S. market, we are expanding our local manufacturing operations in Chattanooga to include state-of-the art manufacture of nuclear and non-nuclear steam turbines as well as new gas turbines,” said Tim Curran, head of Alstom Power for the U.S. and senior vice president and general manager of Boilers North America. “Additionally, this will expand our ability to serve the installed fleet.”

Curran said Alstom has seen growth in the retrofit market as customers look to extend the useful life and improve the environmental profile of the existing fleet. And in the current economic environment, generators are extending expenditures to the extent practical. “Customers are waiting for demand recovery and carbon rules to determine what the playing field is going to be,” he says. “While total electric demand is only down 3 percent, we are hearing that some industrial electric loads have dropped 10 to 20 percent. But economic projections indicate a recovery in the market by the end of this year.”

Power plant owners are repoted to be spending for today rather than the future, waiting for economic conditions to improve. Photo courtesy Hobart Brothers.

Water Wall Welding

It all started when a Hobart Brothers competitor was unable to supply welding materials needed by Southern Co.’s Alabama Power unit to make water wall repairs to some of its coal-fired boilers. So in December 2006, the welding technology company supplied E8018-B2 stick electrodes to repair the boiler tubes. To the utility’s surprise, the Hobart electrode showed some starting porosity and a higher amperage range than the other manufacturer’s product. Although Hobart has been in business for close to 100 years, it had never served the power industry.

“While our product didn’t work as well as the competitor’s, it showed some very favorable characteristics,” said Hobart’s Bruce Morrett. That led Hobart into its first power plant boiler. “We had never seen anything like that and had never seen our product used like that before,” Morrett said.

Hobart’s alloys would work for water wall tube repair, but operated differently than the competition meaning there would have been a learning curve for contractors and boilermakers to use its product, said Morrett.

Alabama Power boilermaker welders with a combined 75 years of experience established evaluation criteria. They described what they really wanted in a stick electrode and developed six components. Based on these performance needs, Hobart’s formulation engineers began product development, in-house trials and evaluations of a new stick electrode.

A key goal was to reduce the amount of water wall weld rejections in a repair job.

“We have designed four unique alloy combinations to use for water wall repair and have been successful in reducing the amount of weld rejects just about everyplace the products have been used,” said Morrett.

“I have seen contractors cite a figure of $250 to repair a rejected weld,” said Morrett. “So a job with 100 welds with 4 percent rejected would cost an extra $1,000.” And since it can take four to eight hours to repair one weld, a cut in the weld reject rate means the welding portion of a job gets done faster. “Maybe they can get that boiler fired up faster and start making money,” Morrett said.—SB